The present inventions relate, generally, to apparatus and methods used in well servicing and treatment operations. More specifically, these inventions relate to downhole apparatus used to selectively provide a flow passage from a tubular string into the wellbore annulus between the tubular string and the casing (or open hole) in which it is run.
As is common in the art, nozzles or ports can be utilized to inject fluid into the annulus surrounding a tubing string to clean various components in the wellbore. For example, cleaning of subsea surfaces and profiles of subsea wellheads, blowout preventers (BOPs) and the like, lifting fluid above liner tops and the like to increase annular flow, etc. In other applications, fluids are injected into the annulus to assist circulation. In a staged fracturing operation, multiple zones of a formation need to be isolated sequentially for treatment. Fracturing valves typically employ sliding sleeves, usually ball-actuated. The sleeves can be one-way valves or can be capable of shifting closed after opening. Initially, operators run the string in the wellbore with the sliding sleeves closed. A setting ball close the interior passageway of the string by seating on a ball seat. This seals off the tubing string so, for example, packers can be hydraulically set. At this point, fracturing surface equipment pumps fluid to open a pressure actuated sleeve so a first zone can be treated. As the operation continues, successively larger balls are dropped down the string to open separate zones for treatment.
Despite the general effectiveness of such assemblies, practical limitations restrict the number of balls that can be run in a single tubing string. Moreover, depending on the formation and the zones to be treated, operators may need a more versatile assembly that can suit their immediate needs. Further, staged sliding sleeves can tend to “skip” positions in response to raised tubing pressure, creating issues with opening a zone to treatment, etc.